In such oilfield operations as hydraulic fracturing, viscosifiers such as polymer systems are commonly used in carrier fluids. A fluid loss additive (FLA) is often used with such carrier fluids to inhibit excessive fluid loss from the carrier fluid. The FLA helps form a filter cake on the surface of the formation. In a fracturing operation, the fluid efficiency is directly related to the amount of fluid loss. High fluid efficiency minimizes the amount of fluid needed to generate a given length of fracture and limits the amount of filter cake that is generated. FLA's can be used to decrease fluid loss and increase the fluid efficiency. The filter cake formed by the FLA reduces permeability at the fluid-rock interface. Conventional FLA usually consists of fine particles, such as mica or silica flour with a broad distribution of particle sizes designed to effectively plug the pore throats of the rock matrix. Starches or other polymers can be added to help fill in the spaces and further reduce the flow.
The FLA is usually injected into the fracture with the initial pad volume used to initiate hydraulic fracturing. After the pad is injected, proppant slurry, that may also contain an FLA, is pumped into the fracture in various stages depending on job design. The proppant is designed to hold the fracture open and allow reservoir fluid to flow through the proppant pack. The proppant slurry generally includes a viscous carrier fluid to keep the proppant from prematurely dropping out of the slurry. After the proppant has been placed in the fracture, the pressure is released and the fracture closes on the proppant. However, it is necessary to remove or break both the viscosifier in the carrier fluid and the filter cake (that may contain viscosifier polymer) so that reservoir fluids can thereafter flow into the fracture and through the proppant pack to the wellbore and the production string.
Conventional fracture design is well known in the art. See, e.g., U.S. Pat. No. 5,103,905, Method of Optimizing the Conductivity of a Propped Fractured Formation, assigned to Schlumberger.
Fracture clean-up issues are well recognized in the literature. Although other systems such as viscoelastic surfactants, gelled oil, slick water, etc. are used, the majority of fluids used to create the fracture and carry the proppants are polymer-based. In most reservoirs with lower permeability, the polymer concentrates as carrier fluid leaks off during the fracturing process. The concentrated polymer hinders fluid flow in the fracture and often results in underperforming fractures. Typical remedies include use of breakers, including encapsulated breakers that allow a significant increase of the breaker loading. The breaker is added to the fluid/slurry and is intended to reduce the viscosity of the polymer-based carrier fluid and facilitate fracture clean-up. Despite high breaker loading, the retained permeability of the proppant pack is still only a fraction of the initial permeability and this has been the accepted situation in the industry.
Recent study of fracture clean-up issues by the applicants has highlighted the mechanisms of polymer concentration and the role played by the filter cake. Contrary to prevailing theory and the industry-accepted practice of modeling polymer concentration as an average involving all the fluid pumped, applicants have discovered that the filter cake can be the main and only medium where significant polymer concentration takes place. This invention discusses a new approach and method that can take advantage of this discovery to significantly improve the clean-up of hydraulic fracturing treatments.
U.S. Pat. Nos. 4,848,467 and 4,961,466 discuss the use of hydroxyacetic acid and similar condensation products which naturally degrade at reservoir temperature to release acid that may be a breaker for some polymers under some conditions and which offer fluid loss control.
U.S. Pat. No. 3,960,736 (Oree) discusses the use of esters to offer a delayed acid which will break the fluid by attacking the polymer and borate crosslinks. Similarly, acid generation mechanisms are employed in U.S. Pat. Nos. 4,387,769 and 4,526,695 (Erbstoesser), which suggest using an ester polymer. U.S. Pat. No. 3,868,998 (Lybarger) also mentions acid generation.
The use of a hydrolysable polyester material for use as an FLA for fluid loss control has also previously been proposed; further, degradation products of such materials have been shown to cause delayed breaking of fracturing fluids. U.S. Pat. No. 4,715,967 discloses the use of polyglycolic acid (PGA) as a fluid loss additive to temporarily reduce the permeability of a formation. SPE paper 18211 discloses the use of PGA as a fluid loss additive and gel breaker for crosslinked hydroxypropyl guar fluids. U.S. Pat. No. 6,509,301 describes the use of acid forming compounds such as PGA as delayed breakers of surfactant-based vesicle fluids, such as those formed from the zwitterionic material lecithin. The preferred pH of these viscosified fluids is above 6.5, more preferably between 7.5 and 9.5. At a lower pH obtained after activation of the delayed breaker, the viscosity decreases.
These references rely on acid as the breaker, which generally has a relatively low activity, but oxidative breakers are much more effective and have become the industry standard for removing polymer damage. In addition, while low pH may break borate crosslinks, it is less effective for breaking the commonly used zirconium and titanium crosslinked gels. In fact, some gel systems employing zirconium or titanium are designed to be effective viscosifiers at low pH.
Encapsulated breakers based on oxidants and/or enzymes are also well known in fracturing systems. Typically, in the prior art the encapsulated breakers are injected with the proppant in the carrier fluid. The breaker capsules are generally the same size as the proppant particles, to facilitate distribution in the proppant pack and promote breakage when the fracture is closed to release the breaker to react with the viscosifier and reduce the viscosity of the carrier fluid to restore permeability to the proppant pack. The major problems with the conventional encapsulated breakers are several. First, the encapsulation process might leave fissures and cracks in the coating, which allow leakage of the breaker and premature reaction. This is largely an artifact because experiments have shown that increasing pressure will close these cracks and limit leakage. Also, the leakage can be controlled by increasing the thickness of the coating. The second problem is that the amount of encapsulated breaker is small compared to the proppant pack volume. Since reaction of the breaker with the polymer is relatively fast, the polymer near the breaker particle is degraded, but the majority of the polymer is not contacted by the breaker at all. Thus, clean-up is limited by the economics that limit the breaker loading. Third, as discussed in more detail below, applicants have found that the breaker is mostly needed in or near the filter cake. This finding is novel for the industry, where prevailing wisdom suggests that the polymer concentration increases uniformly in the fluid throughout the fracture as calculated by heretofore commonly used fracturing models. Fourth, tradition dictates that more breaker is added toward the end of the treatment.
Traditionally, the breaker has been more concentrated in the tail end of the proppant pumping cycle on the theory that it is more important to reduce the viscosity of the carrier fluid closest to the wellbore. More recently it has alternatively been proposed to include the encapsulated proppant at a higher concentration in the earlier proppant injection stages to obtain a viscosity gradient such that the viscosity of the carrier fluid is at a minimum at the tip of the fracture away from the wellbore and increases as the wellbore is approached. U.S. Pat. No. 6,192,985 (Hinkel, et al.) discloses breaker schedules such that the fluid near the fracture tip breaks first creating a viscosity gradient which causes the fluid resident in the tip to move towards the wellbore where it is more easily removed. Breaker is concentrated in the early proppant pumping stages relative to succeeding and later stages so that the fluid furthest from the wellbore breaks faster than fluid near the wellbore, to establish a viscosity gradient. Gas may also be used to foam the fluid in the early pumping stages to induce a density gradient, and fibrous material may be used in the later pumping stages to stabilize the proppant pack as the energized fluid from near the tip squeezes through the near wellbore region.
As used herein, the term “breaker” refers to a chemical moiety or suite of moieties whose primary function is to “break” or reduce the viscosity of the proppant-carrying matrix. Typically, though not always, this occurs by oxidative reduction. According to conventional practice, the choice of breaker depends upon temperature. Exemplary breakers include: bromate, persulfate, enzymes, acids (e.g., fumaric and nitric acid), and organic peroxide. As previously mentioned, conventional breakers are commonly encapsulated to delay their effect. See, e.g., U.S. Pat. No. 4,741,401, Method for Treating Subterranean Formations, assigned to Schlumberger (disclosing selectively permeable encapsulated breakers that burst upon fluid intrusion). See also, e.g., U.S. Pat. No. 4,506,734, Fracturing Fluid Breaker System Which is Activated by Fracture Closure, assigned to The Standard Oil Company and licensed to Schlumberger (disclosing encapsulated breakers that burst due to pressure created by fracture closure). Electrochemical methods for breaking fracturing fluids are also known. See, U.S. Pat. No. 4,701,247, Electrochemical Methods for Breaking High Viscosity Fluids, assigned to Schlumberger.
In addition, “breaker aids” are often used in conjunction with breakers to promote breaker activity. Breaker aids are disclosed in, e.g., U.S. Pat. No. 4,969,526, Non-Interfering Breaker System for Delayed Crosslinked Fracturing Fluids at Low Temperature, assigned to Schlumberger (disclosing and claiming triethanolamine); and, U.S. Pat. No. 4,250,044. Similarly, “retarding agents” (or materials designed to inhibit cross-linking) are operable in conjunction with the present invention. See, e.g., U.S. Pat. No. 4,702,848, Control of Crosslinking Reaction Rate Using Organozirconate Chelate Crosslinking Agent and Aldehyde Retarding Agent, assigned to Schlumberger (disclosing and claiming aldehydes). Copper ion, silver ion, or the like are also known to function as catalysts in conjunction with a chemical breaker, dissolved oxygen, or other oxidant source, accelerating the breaker activity. In addition, different proppant-carrying matrices can be used with different breaker types—e.g., injecting in a first stage a less viscous and/or less dense fluid followed by fluids of lesser mobility. See, e.g., U.S. Pat. No. 5,036,919, Fracturing with Multiple Fluids to Improve Fracture Conductivity, assigned to Schlumberger. The '919 patent discloses, for instance, pumping a zirconate cross-linked fluid followed by a borate cross-linked fluid. Hence, it is known to use different fluids in different stages of the treatment.
As used herein the term “activity,” as in “high-activity breaker” refers to the ability to break (reduce the viscosity) of the proppant-carrying matrix. Hence, activity is a function of chemistry, concentration, and/or temperature. For instance, bromate has a different activity than persulfate; similarly, a greater concentration of bromate has a greater activity than a lower concentration of bromate. In addition, activity can be modulated by encapsulating the breaker (e.g., the '734 patent).
Other references that may be pertinent to the present invention include US2004/0216876; US2005/0034865; and US6394185.
Each of the references mentioned herein are hereby incorporated herein by reference in their entirety for the purpose of US patent practice and other jurisdictions where permitted.